Enhanced oil recovery process to inject low salinity water and gas in carbonate reservoirs

ABSTRACT

The present invention relates to a method to enhance oil recovery from a hydrocarbon reservoir. One aspect of the invention includes injecting high salinity water into the reservoir followed by alternating the injection of low salinity water and gas.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority under 35 U.S.C. §119(e) to U.S. Provisional Patent Application Ser. No. 61/941,869 filed Feb. 19, 2014, which is incorporated herein in its entirety by reference.

FIELD OF THE INVENTION

The invention relates to a method to enhance the recovery of oil in a hydrocarbon reservoir with the injection of low salinity water and gas, such as carbon dioxide, natural gas liquids, liquefied petroleum gas or a gas mixture.

BACKGROUND OF INVENTION

Conventional waterflooding is widely used globally in carbonate oil reservoirs. The ultimate oil recovery from primary production and waterflooding is significantly less than 50%. To recover additional residual oil after waterflooding, gas flooding (such as CO₂), low salinity waterflooding, or other enhanced oil recovery (EOR) methods can be implemented. However, low salinity waterflooding is not economical because it has to displace previously injected higher salinity water to mobilize some of the residual oil (especially when the waterflooding uses seawater in an offshore operation).

SUMMARY OF INVENTION

The present invention relates to a process to enhance oil recovery using low salinity water injection and a gas injection, into oil-wet carbonate reservoirs, which have undergone primary production and waterflooding. This low salinity water injection can be optimized by injecting low salinity water and alternating with a gas or gas mixture (LS-WAG) injection scheme. The gas can be CO₂, nitrogen gas, natural gas liquids (NGL), liquefied petroleum gas (LPG), CO₂+NGL mixture, CO₂+N₂+NGL mixture, and/or N₂+NGL mixture, or any other combination.

Low salinity waterflood after a high salinity waterflood significantly increases the recovery of oil. Following the low salinity flood with CO₂ injection further improved recovery of oil. The EOR process can be implemented as a continuous gas flooding following low salinity waterflood, or as low salinity water-alternating-gas (LS-WAG) process. The LS-WAG EOR process can be effective in mobilizing additional oil from reservoirs, including oil-wet carbonate reservoirs, shale and sandstone, for the following reasons:

-   -   i. Reduces time—Full field low salinity water injection is         expensive because it has to displace the already injected high         salinity water to be beneficial. This takes a long time to reach         the beneficial effects.     -   ii. Time and cost efficiency—Alternating injection of the low         salinity water with miscible solvents (such as, CO₂, Natural Gas         Liquids (NGLs), CO₂+NGL mixture, N₂+NGL mixture) greatly         mobilizes more oil and the already-mobilized oil more         effectively. This also reduces the cost of preparing low         salinity water (desalination) because less low salinity water         will be used.     -   iii. Miscibility achieved—If N₂ is used as injection gas, the         minimum miscibility pressure (MMP) is usually high in most         reservoirs, and miscibility may not be achieved. Whereas, if the         injection streams are, for instance, 50% N₂ plus 50% NGLs, or         20% N₂ and 80% NGLs, or other combinations is injected the         miscibility can be achieved.     -   iv. Minimum miscibility reached quickly—The LS-WAG process         achieves minimum miscibility rather quickly to mobilize more of         the by-passed oil. For instance, pure CO₂ has a MMP of 2470 psia         with a 32 API oil from Middle East carbonate reservoir, but a         50% mixture of CO₂ and 50% NGL would lower MMP to 1615 psia for         the same reservoir oil.

By applying low salinity water-alternating-gas (LS-WAG) approach the enhanced oil recovery process is effective in mobilizing residual oil from oil-wet carbonate reservoirs. This EOR process, for example, can be applied to one of the largest carbonate reservoirs, Upper Zakkum, located offshore Abu Dhabi. This Upper Zakkum reservoir is currently undergoing conventional seawater flooding at injection rate of 800 MBW/day. The average daily oil production is 560 MSTB. This LS-WAG EOR process can be beneficial to this field to produce significant amount of additional oil.

The present invention takes advantage of the synergistic effect of mobilizing residual oil due to both low salinity water and gas solvents (CO₂, NGL, LPG, nitrogen gas, CO₂+NGL mixture, CO₂+N₂+NGL mixture, N₂+NGL mixture and mixtures thereof). Though not wanting to be bound by theory, the low salinity water is believed to alter the wettability state of the reservoir towards water-wet and lower interfacial tension (IFT) between brine and oil. The solubility of carbon dioxide is higher in low salinity water as compared to the solubility of carbon dioxide in higher salinity water, which means higher carbonic acid concentration when applied with low salinity water, and this leads to improved wettability alteration towards water-wet state and further reduction in IFT. In addition, there is a decrease in oil viscosity and further increase in oil swelling can be achieved compared to a conventional WAG process, resulting in improved oil mobility. Thus, the method results in enhanced oil recovery from the reservoir.

An aspect of the invention is a method to enhance recovery of oil in a hydrocarbon reservoir. The method includes injecting low salinity water into the reservoir, then injecting a gas into the reservoir after the injection of the low salinity water into the reservoir.

Another aspect of the invention is a method to enhance oil recovery from a hydrocarbon reservoir, where high salinity water is injected into a reservoir. Low salinity water is then injected into the reservoir following the injection of the high salinity water. The salinity level of the low salinity water is less than a salinity level of the high salinity water. After the low salinity injection, a gas is injected into the reservoir following a subsequent injection of the low salinity water into the reservoir. Subsequently, the low salinity water and the gas are injected in alternation manner.

An aspect of the present invention is a method to enhance recovery of a hydrocarbon in a reservoir, where the reservoir is flooded with high salinity water. Then a first injection of low salinity water is injected into the reservoir, where at least about 0.2 of a pore volume of the reservoir is occupied by the low salinity water. Following the first injection of the low salinity water, a first injection of a gas is injected into the reservoir, where at least about 0.2 of the pore volume of the reservoir is occupied by the gas. Subsequently, the low salinity water and the gas are injected in an alternating manner.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates three cores using the Huppler technique for sample 1 discussed in Table 1 at the end of the experiment;

FIG. 2 illustrates a schematic of the three phase core flooding experiment;

FIG. 3 illustrates the overall experimental procedure;

FIG. 4 illustrates the oil recovery factor (RF) and pressure difference between injections and production end as a function of the pore volume injected for protocol discussed in Example 1;

FIG. 5 illustrates the oil recovery factor (RF) and pressure difference between injections and production end as a function of the pore volume injected for protocol discussed in Example 2;

FIG. 6 illustrates core discs corresponding to measurement condition A, measurement condition B, measurement condition C, and measurement condition D;

FIG. 7 illustrates the contact angle measurements of carbonate/sandstone/Three Forks discs at corresponding to measurement condition A, measurement condition B, measurement condition C, and measurement condition D; and

FIG. 8 illustrates the contact angle between carbonate/sandstone/Three Forks discs and oil-droplet at measurement conditions A, B, and C.

DETAILED DESCRIPTION

The present invention relates to methods to recover oil from a reservoir. An aspect of the invention relates to a method to recover oil from a reservoir, which includes injecting high salinity water into the reservoir followed by alternating the injection of low salinity water and gas. Another aspect of the invention includes a method for the enhanced recovery of oil from a reservoir where oil had previously been recovered.

As provided herein, the abbreviations as used within this patent application has the following meanings:

“High salinity water” means a higher salinity level in water compared to a salinity level in low salinity water. By way of example only, high salinity water may be seawater, formation water, produced water and combinations thereof. High salinity water also includes within its definition the term waterflooding as it is generally known in the art as in typical operations. “Low salinity water” means water with a lower salinity level compared to the salinity level in a high salinity water. By way of example only, high salinity water may be seawater, while low salinity water may be desalinated seawater. Other examples of low salinity water may include, but are not limited to, at least one of desalinated seawater, diluted seawater, desalinated hydrocarbon reservoir formation water, diluted hydrocarbon reservoir water, river water, lake water, or formation water. Alternatively, low salinity water may be seawater, while high salinity water may be water with a higher salinity than the seawater. Thus, high salinity water is defined by the comparison to the low salinity water, and vice versa. “LS₂” means low salinity where the salinity level is lower than the high salinity water (for example the seawater) by a factor of about 2. This low-salinity water can be prepared by a dilution or desalination processes. “LS₄” means low salinity where the salinity level is lower than the high salinity water (for example the seawater) by a factor of about 4. This low-salinity water can be prepared by a dilution or desalination processes. “LS₅₀” means low salinity where the salinity level is lower than the high salinity water (for example the seawater) by a factor of about 50. This low-salinity water can be prepared by a dilution or desalination processes. “LS_(x)” means low salinity where the salinity level is lower than the high salinity water (for example the seawater) by a factor of about “x”. This low-salinity water can be prepared by a dilution or desalination processes. “S_(or),” means residual oil saturation. “S_(wi)” means initial water saturation. “SW” means seawater. “MMP” means minimum miscibility pressure. “RF” means recovery factor. “WAG” means water-alternating-gas. “LS-WAG” or “LSWAG” means low salinity water-alternating-gas. “LS-WACO₂” means low salinity water-alternating-CO₂ gas. “LSWAG ratio” means the ratio of the low salinity water to the gas. By way of example only, if the WAG ratio is 1:1, the same amount by pore volume of water is injected as gas. “Slug size” relates to the pore volume of the low salinity water and the pore volume of the gas.

One skilled in the art would understand that the operating conditions of the reservoir will depend upon the characteristics of the reservoir. Thus, the temperature, flow rate of the high salinity water, flow rate of the low salinity water, flow rate of the gas, duration of the high salinity waterflood, duration of the low salinity waterflood, duration of the gas injection (which may be measured by the pore volume injected), the water cut at completion of the operation and other operating parameters may not be discussed. However, one skilled in the art would understand how to determine the operating parameters for the reservoir.

An aspect of the present invention is a method to recover oil from a reservoir by injecting high salinity water into the reservoir, followed by injecting low salinity water into the reservoir followed by injecting a gas into the reservoir. The low salinity water and the gas injections can be alternated into the reservoir.

As described in the definitions, the salinity level of the low salinity water is less than the salinity level of the high salinity water. The low salinity water may be formed by decreasing the salinity level of the high salinity water to form the low salinity water. By way of example the high salinity water may be decreased by desalinating the high salinity water. In some embodiments, the salinity level of the low salinity water can be half the salinity level of the high salinity water. In some embodiments, the salinity level of the low salinity water can be a quarter the salinity level of the high salinity water. In some embodiments, the low salinity water can be “x” times the salinity level of the high salinity water, where x is the amount the salinity is decreased compared to the high salinity water. The benefits of the present invention may be increased when the salinity in the low salinity water is decreased. Thus, in a preferred embodiment, the low salinity water may be fresh water, though it is understood that the use of fresh water may be constricted by economic factors. Furthermore, the salinity of the low salinity water may be the same or altered with each subsequent injection. Thus, by way of example only, the salinity level of the first low salinity water injection may be about LS₂, which the salinity level of the second low salinity water injection may be LS₃, then the salinity of the third low salinity water injection may be LS₄.

The pore volume of the reservoir may be occupied by the low salinity water injected into the reservoir, which may be dependent upon the reservoir. In some embodiments, the pore volume of the reservoir occupied by the low salinity water injected into the reservoir may be about 1 (i.e. about 100%). In some embodiments, the pore volume of the reservoir occupied by the low salinity water may be greater than about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about 0.6, about 0.7, about 0.8, about 0.9 or about 1. In some embodiments, the pore volume of the first low salinity water injection may be less than or equal to the pore volume of subsequent low salinity water injections. In some embodiments where the high salinity water was injected first, the pore volume of the reservoir of the low salinity water may be about 1, such that the majority or all of the high salinity water that was injected into the reservoir may be displaced by the low salinity water.

The gas can be any suitable gas, including but not limited to, carbon dioxide, natural gas liquids, liquid petroleum gas, nitrogen gas, and combinations thereof. The natural gas liquids can be intermediate hydrocarbons, such as C₂-C₅ gas, and combinations thereof. Liquefied petroleum gas (LPG) can be C₃ (propane) or C₄ (butane) or combinations thereof. Preferably, the gas may be carbon dioxide or NGLs. More preferably, the gas may be carbon dioxide. In some embodiments, at least some of the natural gas liquid or at least some of the LPG may be recycled from the reservoir. One skilled in the art would understand that the recycled natural gas may need to be scrubbed to remove any condensate or water within the gas prior to injection into the reservoir.

In some embodiments, the pore volume of the reservoir may be occupied by the gas, such that the gas may occupy greater than about 0, about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about 0.6, about 0.7, about 0.8, about 0.9 or about 1. In some embodiments, the pore volume of the first gas injection may be higher than the pore volume of subsequent gas injections. In some embodiments, the pore volume of the first gas injection may be the same or less than the pore volume of subsequent gas injections.

A slug size may be used to characterize the relationship between the low salinity water injection and gas injection can be alternated in a slug size of about 0.5 pore volume. In some embodiments, the low salinity water injection may be alternated in a slug size of about 0.1 to about 1 pore volume.

The method may be used to recover oil from an oil reservoir. In some embodiments, the oil reservoir may be an oil-wet carbonate reservoir, a shale reservoir or a sandstone reservoir. One skilled in the art would understand that the reservoir may comprise a single reservoir or multiple reservoirs, or a single well or multiple wells. The reservoir may be offshore or onshore. The low salinity water and the gas can be injected into the reservoir by alternating the injection of the low salinity water and gas. The alternating injections may be continued for any duration, for example, until the water cut is at least about 80 mass %. In some embodiments, the water cut can be about 85 mass %, about 90 mass %, and about 95 mass %. In some embodiments, the operation cost may permit or prevent feasibility of the project.

Another aspect of the present invention is a method to enhance recovery of oil in a reservoir. The method includes waterflooding the reservoir with low salinity water then injecting a gas into the reservoir. The method may further include a high salinity waterflood prior to waterflooding the reservoir with the low salinity water. The method can further include alternating injecting the low salinity water into the reservoir, and injecting the gas into the reservoir.

As described in the definitions, the salinity level of the low salinity water is less than the salinity level of the high salinity water. The low salinity water may be formed by decreasing the salinity level of the high salinity water to form the low salinity water. By way of example the high salinity water may be decreased by desalinating the high salinity water. In some embodiments, the salinity level of the low salinity water can be half the salinity level of the high salinity water. In some embodiments, the salinity level of the low salinity water can be a quarter the salinity level of the high salinity water. In some embodiments, the low salinity water can be “x” times the salinity level of the high salinity water, where x is the amount the salinity is decreased compared to the high salinity water. The benefits of the present invention may be increased when the salinity in the low salinity water is decreased. Thus, in a preferred embodiment, the low salinity water may be fresh water, though it is understood that the use of fresh water may be constricted by economic factors. Furthermore, the salinity of the low salinity water may be the same or altered with each subsequent injection. Thus, by way of example only, the salinity level of the first low salinity water injection may be about LS₂, which the salinity level of the second low salinity water injection may be LS₃, then the salinity of the third low salinity water injection may be LS₂.

The pore volume of the reservoir may be occupied by the low salinity water injected into the reservoir, which may be dependent upon the reservoir. In some embodiments, the pore volume of the reservoir occupied by the low salinity water injected into the reservoir may be about 1. In some embodiments, the pore volume of the reservoir occupied by the low salinity water may be greater than about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about 0.6, about 0.7, about 0.8, about 0.9 or about 1. In some embodiments, the pore volume of the first low salinity water injection may be less than or equal to the pore volume of subsequent low salinity water injections. In some embodiments where the high salinity water was injected first, the pore volume of the reservoir of the low salinity water may be about 1, such that the majority or all of the high salinity water that was injected into the reservoir may be displaced by the low salinity water

The gas can be any suitable gas, including but not limited to, carbon dioxide, natural gas liquids, liquid petroleum gas, nitrogen gas, and combinations thereof. The natural gas liquids can be intermediate hydrocarbons, such as C₂-C₅ gas, and combinations thereof. Liquefied petroleum gas (LPG) can be C₃ (propane) or C₄ (butane) or combinations thereof. Preferably, the gas may be carbon dioxide or NGLs. More preferably, the gas may be carbon dioxide. In some embodiments, at least some of the natural gas liquid or at least some of the LPG may be recycled from the reservoir. One skilled in the art would understand that the recycled natural gas may need to be scrubbed to remove any condensate or water within the gas prior to injection into the reservoir.

In some embodiments, the pore volume of the reservoir may be occupied by the gas, such that the gas may occupy greater than about 0, about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about 0.6, about 0.7, about 0.8, about 0.9 or about 1. In some embodiments, the pore volume of the first gas injection may be higher than the pore volume of subsequent gas injections. In some embodiments, the pore volume of the first gas injection may the same or less than the pore volume of subsequent gas injections.

A slug size may be used to characterize the relationship between the low salinity water injection and gas injection can be alternated in a slug size of about 0.5 pore volume. In some embodiments, the low salinity water injection may be alternated in a slug size of about 0.1 to about 1 pore volume.

The method may be used to recover oil from an oil reservoir. In some embodiments, the oil reservoir may be an oil-wet carbonate reservoir, a shale reservoir or a sandstone reservoir. One skilled in the art would understand that the reservoir may comprise a single reservoir or multiple reservoirs, or a single well or multiple wells. The reservoir may be offshore or onshore. The low salinity water and the gas can be injected into the reservoir by alternating the injection of the low salinity water and gas. The alternating injections may be continued for any duration, for example, until the water cut is at least about 80 mass %. In some embodiments, the water cut can be about 85 mass %, about 90 mass %, and about 95 mass %. In some embodiments, the operation cost may permit or prevent feasibility of the project.

Another aspect of the present invention is a method to enhance recovery of a hydrocarbon in a reservoir. The method includes waterflooding the reservoir with high salinity water, then injecting low salinity water into the reservoir, then injecting a gas into the reservoir. The method can further include alternating the injection of low salinity water and gas into the reservoir.

As described in the definitions, the salinity level of the low salinity water is less than the salinity level of the high salinity water. The low salinity water may be formed by decreasing the salinity level of the high salinity water to form the low salinity water. By way of example the high salinity water may be decreased by desalinating the high salinity water. In some embodiments, the salinity level of the low salinity water can be half the salinity level of the high salinity water. In some embodiments, the salinity level of the low salinity water can be a quarter the salinity level of the high salinity water. In some embodiments, the low salinity water can be “x” times the salinity level of the high salinity water, where x is the amount the salinity is decreased compared to the high salinity water. The benefits of the present invention may be increased when the salinity in the low salinity water is decreased. Thus, in a preferred embodiment, the low salinity water may be fresh water, though it is understood that the use of fresh water may be constricted by economic factors. Furthermore, the salinity of the low salinity water may be the same or altered with each subsequent injection. Thus, by way of example only, the salinity level of the first low salinity water injection may be about LS₂, which the salinity level of the second low salinity water injection may be LS₃, then the salinity of the third low salinity water injection may be LS₂.

The pore volume of the reservoir may be occupied by the low salinity water injected into the reservoir, which may be dependent upon the reservoir. In some embodiments, the pore volume of the reservoir occupied by the low salinity water injected into the reservoir may be about 1. In some embodiments, the pore volume of the reservoir occupied by the low salinity water may be greater than about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about 0.6, about 0.7, about 0.8, about 0.9 or about 1. In some embodiments, the pore volume of the first low salinity water injection may be less than or equal to the pore volume of subsequent low salinity water injections. In some embodiments where the high salinity water was injected first, the pore volume of the reservoir of the low salinity water may be about 1, such that the majority or all of the high salinity water that was injected into the reservoir may be displaced by the low salinity water

The gas can be any suitable gas, including but not limited to, carbon dioxide, natural gas liquids, liquid petroleum gas, nitrogen gas, and combinations thereof. The natural gas liquids can be intermediate hydrocarbons, such as C₂-C₅ gas, and combinations thereof. Liquefied petroleum gas (LPG) can be C₃ (propane) or C₄ (butane) or combinations thereof. Preferably, the gas may be carbon dioxide or NGLs. More preferably, the gas may be carbon dioxide. In some embodiments, at least some of the natural gas liquid or at least some of the LPG may be recycled from the reservoir. One skilled in the art would understand that the recycled natural gas may need to be scrubbed to remove any condensate or water within the gas prior to injection into the reservoir.

In some embodiments, the pore volume of the reservoir may be occupied by the gas, such that the gas may occupy greater than about 0, about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about 0.6, about 0.7, about 0.8, about 0.9 or about 1. In some embodiments, the pore volume of the first gas injection may be higher than the pore volume of subsequent gas injections. In some embodiments, the pore volume of the first gas injection may the same or less than the pore volume of subsequent gas injections.

A slug size may be used to characterize the relationship between the low salinity water injection and gas injection can be alternated in a slug size of about 0.5 pore volume. In some embodiments, the low salinity water injection may be alternated in a slug size of about 0.1 to about 1 pore volume.

The method may be used to recover oil from an oil reservoir. In some embodiments, the oil reservoir may be an oil-wet carbonate reservoir, a shale reservoir or a sandstone reservoir. One skilled in the art would understand that the reservoir may comprise a single reservoir or multiple reservoirs, or a single well or multiple wells. The reservoir may be offshore or onshore. The low salinity water and the gas can be injected into the reservoir by alternating the injection of the low salinity water and gas. The alternating injections may be continued for any duration, for example, until the water cut is at least about 80 mass %. In some embodiments, the water cut can be about 85 mass %, about 90 mass %, and about 95 mass %. In some embodiments, the operation cost may permit or prevent feasibility of the project.

Another aspect of the invention is a method to enhance recovery of a hydrocarbon in a reservoir. The method includes injecting a gas into the reservoir followed by waterflooding the reservoir with a low salinity water. The method can further include alternating the injection of the gas and low salinity water into the reservoir.

As described in the definitions, the salinity level of the low salinity water is less than the salinity level of the high salinity water. The low salinity water may be formed by decreasing the salinity level of the high salinity water to form the low salinity water. By way of example the high salinity water may be decreased by desalinating the high salinity water. In some embodiments, the salinity level of the low salinity water can be half the salinity level of the high salinity water. In some embodiments, the salinity level of the low salinity water can be a quarter the salinity level of the high salinity water. In some embodiments, the low salinity water can be “x” times the salinity level of the high salinity water, where x is the amount the salinity is decreased compared to the high salinity water. The benefits of the present invention may be increased when the salinity in the low salinity water is decreased. Thus, in a preferred embodiment, the low salinity water may be fresh water, though it is understood that the use of fresh water may be constricted by economic factors. Furthermore, the salinity of the low salinity water may be the same or altered with each subsequent injection. Thus, by way of example only, the salinity level of the first low salinity water injection may be about LS₂, which the salinity level of the second low salinity water injection may be LS₃, then the salinity of the third low salinity water injection may be LS₂.

The pore volume of the reservoir may be occupied by the low salinity water injected into the reservoir, which may be dependent upon the reservoir. In some embodiments, the pore volume of the reservoir occupied by the low salinity water injected into the reservoir may be about 1. In some embodiments, the pore volume of the reservoir occupied by the low salinity water may be greater than about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about 0.6, about 0.7, about 0.8, about 0.9 or about 1. In some embodiments, the pore volume of the first low salinity water injection may be less than or equal to the pore volume of subsequent low salinity water injections. In some embodiments where the high salinity water was injected first, the pore volume of the reservoir of the low salinity water may be about 1, such that the majority or all of the high salinity water that was injected into the reservoir may be displaced by the low salinity water

The gas can be any suitable gas, including but not limited to, carbon dioxide, natural gas liquids, liquid petroleum gas, nitrogen gas, and combinations thereof. The natural gas liquids can be intermediate hydrocarbons, such as C₂-C₅ gas, and combinations thereof. Liquefied petroleum gas (LPG) can be C₃ (propane) or C₄ (butane) or combinations thereof. Preferably, the gas may be carbon dioxide or NGLs. More preferably, the gas may be carbon dioxide. In some embodiments, at least some of the natural gas liquid or at least some of the LPG may be recycled from the reservoir. One skilled in the art would understand that the recycled natural gas may need to be scrubbed to remove any condensate or water within the gas prior to injection into the reservoir.

In some embodiments, the pore volume of the reservoir may be occupied by the gas, such that the gas may occupy greater than about 0, about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about 0.6, about 0.7, about 0.8, about 0.9 or about 1. In some embodiments, the pore volume of the first gas injection may be higher than the pore volume of subsequent gas injections. In some embodiments, the pore volume of the first gas injection may the same or less than the pore volume of subsequent gas injections.

A slug size may be used to characterize the relationship between the low salinity water injection and gas injection can be alternated in a slug size of about 0.5 pore volume. In some embodiments, the low salinity water injection may be alternated in a slug size of about 0.1 to about 1 pore volume.

The method may be used to recover oil from an oil reservoir. In some embodiments, the oil reservoir may be an oil-wet carbonate reservoir, a shale reservoir or a sandstone reservoir. One skilled in the art would understand that the reservoir may comprise a single reservoir or multiple reservoirs, or a single well or multiple wells. The reservoir may be offshore or onshore. The low salinity water and the gas can be injected into the reservoir by alternating the injection of the low salinity water and gas. The alternating injections may be continued for any duration, for example, until the water cut is at least about 80 mass %. In some embodiments, the water cut can be about 85 mass %, about 90 mass %, and about 95 mass %. In some embodiments, the operation cost may permit or prevent feasibility of the project.

EXAMPLE Example 1

Two core-flood experiment of seawater flood, followed by three sets of low salinity-water flood, flowed by CO₂ flood is performed on Facies 5 (F5) of Reservoir I core samples from a giant carbonate oil field in the Middle East. Facies description and geologic study of the reservoir can be found in Jobe (2013). Cores were prepared, cleaned using toluene and methanol. The petrophysical properties such as permeability and porosity are measured using Core Measurement System (CMS-300). Table 1 lists rock properties of samples used in the two core-flood experiments. The core type for all samples was F5 carbonate core (composite core). The diameter of the samples was about 1.5 inches and the PV was about 29.98 cc for Example 1 and 34.864 cc for Example 2. The miscible CO₂ flooding following seawater and low salinity waterflooding (e.g. LS₂, LS₄, LS_(x)) on composite carbonate cores. Eight weeks of aging applied. The miscible CO₂ flooding following seawater and low salinity waterflooding (e.g. LS₂, LS₄, LS_(x)) on composite carbonate cores. Eight weeks of aging applied.

TABLE 1 Exp. # L (in) φ, % k_(air) (md) 1 a 1.88 26.9 3.38 b 1.82 21.1 1.16 c 1.896 14.5 0.76 2 a 1.7 18.23 1.49 b 1.88 21.35 7.04 c 1.881 26.95 3.81 Tests were performed on a stack with three cores each. Ultra-high speed centrifuge (ACES 200) is used to saturate the cores with formation brine. A composite core is formed by combining the three cores using Huppler technique as illustrated in FIG. 1 for sample 1 discussed in Table 1. The image of the core samples illustrated in FIG. 1 was taken at the end of the experiment. The total length of the composite core was about 5.596 inches. The flooding direction was from left to right. Another set of stacked cores from F5 were used for core-flood experiment #2. The composite core was placed in a high-pressure-high-temperature (HPHT) core flooding equipment, Formation Response Tester (FRT 6100). Three additional pore volumes (PV) of brine were injected into the composite core inside the core-flood equipment to ensure full brine saturation and no air in trapped in the pores. A confining pressure of about 2,300 psia, back pressure regulator (BPR) of about 1800 psia, and reservoir temperature of about 195° F. were applied to the hassler type core holder unit during the flooding and aging processes. The schematic of the three phase core flooding experiment setup is illustrated in FIG. 2. Up to the three sets of low salinity flooding, the production fluids are collected in the fraction collector. For the case of gas flooding, the separator is used to collect the production fluid; and the produced gas is measured using the gas flow meter (GFM); and the oil/water are collected in a graduated tube and centrifuged and measured.

FIG. 3 illustrates the overall experimental procedure. First the core was prepared and cleaned, the petrophysical properties were measured and the fluid was prepared and measured. The brine was saturated with brine, then flooded with oil. The core was aged, then flooded again with oil. Next the samples were flooded with water, followed by a series of low salinity waterflooding. Finally, the samples were flooded with gas, specifically CO₂.

Following the overall experimental procedure set forth in FIG. 3, fifteen pore volume of crude oil was then injected at about 0.1 cc/min flow rate to achieve the residual water saturation (S_(wi)), and also to determine the oil relative permeability end point. The oil composition and oil properties are listed in Table 2 and Table 3, respectively. Oil/brine viscosities at reservoir temperature of about 195° F. are given in Table 4.

TABLE 2 Components Mole % CO₂ 1.047879 N₂ 0.000000 C₁ 13.782727 C₂ 5.455455 C₃ 6.584545 C₄* 5.722424 C₅* 5.267273 C₉* 33.632886 C₂₁* 21.938239 C₄₇* 6.568572 *Lumped components

TABLE 3 Fluid Type API ° SG Crude Oil 32 0.865

TABLE 4 Fluid Type Viscosity (cP) crude oil 3.0 Brine/seawater/ 0.535 low salinity water

The composite core was aged for 8 weeks to restore wettability. Four PV of crude oil was injected to saturate the composite core with crude oil after wettability restoration and determine relative permeability to oil. Seven PV of sea water was then injected at about 0.1 cc/min to displace the oil and determine the residual oil saturation to seawater. This step also was used to determine the seawater relative permeability end point. Pressure and temperature conditions of the core flooding unit were kept the same as in the previous situation. A recovery factor (RF) of about 61.2% was obtained during seawater flooding.

Three sets of low salinity waterflooding were performed following the seawater flooding. The first low salinity flood (LS₂) is obtained by diluting the seawater twice, and LS₄ is five times diluted seawater and LS₅₀ is fifty times diluted seawater. Table 5 is composition of the seawater (SW) and three sets of low salinity water (LS₂, LS₄ and LS₅₀).

TABLE 5 Brine/ Compound (kppm) Na₂SO₄ CaCl₂*2H₂O MaCl₂*6H₂O NaCl TDS SW 4.891 1.915 13.550 30.99 51.346 LS₂ 2.446 0.958 6.775 15.50 25.679 LS₄ 1.223 0.479 3.388 7.75 12.840 LS₅₀ 0.098 0.038 0.271 0.620 1.027

The incremental oil recovery of the first two low salinity waterflooding EOR process are about 6% and about 1.1% respectively. No additional oil was recovered during the third low salinity waterflood. A constant about 0.1 cc/min injection rate of 5 PV was applied in each of the three low salinity waterflood EOR processes. An increase of injectivity as witnessed by the reduction in pressure drop is observed during the low salinity waterflood as compared to seawater flooding as illustrated in FIG. 4. Pressure and temperature conditions of the core flooding unit were kept the same as in the previous situation.

FIG. 4 illustrates the oil RF and pressure difference between injection and production end (ΔP) as a function pore volume injected (PV inj). During seawater flooding (SW), about 61.2% oil was recovered. During the three sets of low salinity waterflood (LS₂, LS₄ and LS₅₀) EOR process, about additional 7.1% oil was recovered. And finally during the CO₂ miscible flood, about additional 14.2% oil was recovered.

Finally, fourteen PV continuous CO₂ gas flooding was performed at about 0.3 cc/min following the three sets of low salinity waterflooding. During the CO₂ flooding, the confining pressure and back-pressure regulator (BPR) of the core older unit were raised about 2700 psia and about 2500 psia respectively to achieve miscibility. An incremental oil recovery of about 14.2% has been obtained during the miscible CO₂ flooding. The injectivity to CO₂ flood is observed to increase as witnessed by the reduction of pressure drop during the CO₂ flooding period as illustrated in FIG. 4.

The MMP of crude oil and CO₂ gas is measured using the rising-bubble apparatus (RBA) as about 2500 psia. The MMP crude oil and CO₂ gas also calculated using the Multiple Mixing Cell (MMC) approach (Ahmadi and Johns, 2011; Teklu et al., 2012) and good match has been achieved with the experimental data. The MMP of crude oil with CO₂ gas is determined using MMC approach as about 2470 psia. The MMP of rich gas, nitrogen, mixture of rich gas and CO₂, and mixture of rich gas and nitrogen gas with the crude oil is also determined using MMC approach. Table 6 is the MMP of the crude oil with different injection gas scenarios.

TABLE 6 Gas injection cases MMP, psia 100% CO₂ 2470 100% NGLs* 830 50% CO₂ and 50% NGLs* 1615 100% N₂ 14,000 50% N₂ and 50% NGLs* 4860 20% N₂ and 80% NGLs* 1400 *[0.61 C₂, 0.22 C₃, 0.095 C₄, 0.065 C₅ and 0.01 C₆] is the composition of NGLs used in this study.

Example 2

The core-flood protocol applied to the second core-flood on a second F5 sample from Reservoir I was similar to the first core-flood protocol. About 52.8% oil was recovered during waterflooding, about 5.2% additional oil was recovered during LS₂ flooding, and about 0.4% and no additional oil was recovered during LS₄ and LS₅₀ flooding cycles, respectively. Finally, about 25% additional oil was recovery during about 10 PV continuous miscible CO₂ flooding. FIG. 5 illustrates the oil recovery factor and pressure drop as a function pore volume injected.

Example 3

The interfacial tension (IFT) between brine and oil as well as wettability of core discs with oil was measured at ambient conditions. Drop Shape Analyzer, DSA 100, was used to measure contact angles between solids and fluids and IFT between different fluids. For both IFT and wettability measurements, the effect of salinity of brine was investigated. About 32° API gravity crude oil from Reservoir I was used in both IFT and wettability measurement. Also the Reservoir I formation brine (FB) was used in the IFT and wettability measurements. Pendant drop method was used to determine the IFT, whereas, captive oil droplet contact angle measurement method was applied during the contact angle measurements. Detailed discussion on the IFT and contact angle measurement and additional results can be found in Teklu et al. (2014), Teklu et al., (2015), and Alameri et al. (2014).

Wettability measurements were performed on crude-aged F5 carbonate, Berea sandstone, and Three Forks core discs at measurement conations A, B, C and D. The measurement condition A is the base case contact angle measurement, where the core discs were crude-aged for three weeks at reservoir temperature and the surrounding brine during contact angle measurements between the disc and oil-drop late was seawater (SW). The measurement condition B is where the crude-aged discs were kept for two days in a piston at about 2,500 psi inside a mixture of about 300 ml seawater (SW) and about 200 ml CO₂. The core disc and SW—CO₂ mixture were then extracted from the piston after slowly releasing the pressure. The contact angle measurements were performed at room conditions between oil-droplets and the core discs where the surrounding fluid was the SW—CO₂ mixture extracted from the cylinder hence has less CO₂ concentration as the pressure was atmospheric. This was to mimic the reservoir condition of seawater alternated CO₂ EOR process. Measurement condition C occurred when the core discs that underwent measurement condition B were kept for additional about two days in a piston at about 2,500 psi inside a mixture of about 300 ml LS₂ and about 200 ml CO₂. The core discs and LS₂—CO₂ mixture were then extracted from the piston after slowly releasing the pressure. The contact angle measurements were then performed at room conditions between oil-droplets and the core discs where the surrounding fluid was the LS₂—CO₂ mixture extracted from the cylinder hence has less CO₂ concentration as the pressure was atmospheric. This measurement condition was to mimic the reservoir condition of low salinity water alternated with CO₂ EOR process. About 2,500 psi in both measurement conditions B and C were chosen to mimic miscible CO₂ situation. Measurement condition D occurred when the core discs were cleaned and un-aged and the surrounding fluid was seawater (SW). This measurement condition was reported here for comparison reason to show how reservoirs wettability was altered in secondary and tertiary recovery mechanisms where condition D is the extreme possible situation when the reservoir pore is ‘cleaned’ during many pore volume CO₂ injection. In the cleaning process of the core discs, toluene was applied in Soxhlet extractor until no oil trace was seen from the discs and methanol was used to remove if any salt was present and then toluene was again used to make sure the core discs are clean.

FIG. 6 illustrates the core discs corresponding to measurement conditions A, B, C, and D. Pictures of the carbonate, Berea sandstone, and Three Forks discs used for contact angle measurement at measurement conditions A, B, C and D. Note that measurement conditions A, B and C were performed on the same discs whereas D was performed on adjacent discs (scale: about 0.5 cm by about 0.5 cm square paper).

FIGS. 7 and 8, and Table 7 illustrate the contact angle measurement conditions A, B, and C for carbonate, Berea sandstone and Three Forks core discs. As illustrated in FIG. 7, the wettability of carbonate, Berea sandstone, and Three Forks constantly changed towards water wet wettability state as measurements progressed from measurement condition “A” to “D.” This implies that wettability alteration was one of the main mechanisms in mobilizing residual oil in hybrid low salinity and CO₂ flooding EOR process. FIG. 8 illustrates the contact angle between carbonate/sandstone/Three Forks discs and oil-droplet at measurement conditions A, B, and C. The first, second, and third row of FIG. 8 corresponds to carbonate, Berea sandstone, and The Three Forks core disc cases respectively. And the first, second, and third columns of FIG. 8 correspond to measurement condition A, B, and C respectively. The volume of the oil droplets ranged from about 4 to 15μ liters.

Brine pH and oil-brine IFT measurements were also performed where the brine was the SW—CO₂ and LS₂—CO₂ mixtures after the pressure was released to atmospheric pressure and most of the CO₂ were escaped from the solution. Table 8 illustrates the IFT between oil and brine over varying pHs of the brine. As illustrated in Table 8, at atmospheric pressure and room temperature, a moderate IFT and pH reduction due to CO₂ solution in the mixture was observed as compared to the SW and LS₂ brines without CO₂. Atmospheric conditions were used for the SW—CO₂ mixture and the LS₂—CO₂ mixture. Further IFT and brine pH reduction is anticipated at reservoir pressure.

TABLE 7 Measurement Contact Angle, θ, in degrees condition Carbonate Berea Sandstone Three Forks A 133.6 94.6 116.6 B 36.1 60.0 40.8 C 31.2 46.5 36.6 D 21.0 20.4 27.0

TABLE 8 IFT between oil and Brine brine, dynes/cm pH SW 16.62 6.60 SW-CO₂ mixture 11.96 5.50 LS₂ 18.85 6.53 LS₂-CO2 mixture 12.34 5.29

The foregoing description of the present invention has been presented for purposes of illustration and description. Furthermore, the description is not intended to limit the invention to the form disclosed herein. Consequently, variations and modifications commensurate with the above teachings, and the skill or knowledge of the relevant art, are within the scope of the present invention. The embodiment described hereinabove is further intended to explain the best mode known for practicing the invention and to enable others skilled in the art to utilize the invention in such, or other, embodiments and with various modifications required by the particular applications or uses of the present invention. It is intended that the appended claims be construed to include alternative embodiments to the extent permitted by the prior art. 

1. A method to enhance recovery of oil in a hydrocarbon reservoir, comprising: injecting a low salinity water into the reservoir; and injecting a gas into the reservoir after the injection of the low salinity water into the reservoir.
 2. The method of claim 1, further comprising alternating injecting the low salinity water into the reservoir, and injecting the gas into the reservoir.
 3. The method of claim 1, wherein the gas is at least one of a carbon dioxide, a natural gas liquid, a nitrogen, a liquid petroleum gas and combinations thereof.
 4. The method of claim 1, wherein the gas is produced from the reservoir.
 5. The method of claim 1, further comprising injecting a high salinity water into the reservoir prior to injecting the low salinity water into the reservoir.
 6. The method of claim 5, wherein the high salinity water is at least one of seawater, produced hydrocarbon reservoir water, and combinations thereof.
 7. The method of claim 1, wherein the low salinity water is at least one of a desalinated seawater, a diluted seawater, a desalinated hydrocarbon reservoir formation water, a diluted hydrocarbon reservoir water, a river water, a lake water, or a produced hydrocarbon reservoir water.
 8. The method of claim 1, wherein the reservoir is an oil-wet carbonate reservoir, a shale reservoir or a sandstone reservoir.
 9. A method to enhance oil recovery from a hydrocarbon reservoir, comprising: injecting high salinity water into the reservoir; injecting a low salinity water into the reservoir following the injection of the high salinity water, wherein a salinity level of the low salinity water is less than a salinity level of the high salinity water; injecting a gas into the reservoir following the injection of the low salinity water; and alternating the injection of the low salinity water and the gas into the reservoir.
 10. The method of claim 9, wherein the gas is at least one of a carbon dioxide, a natural gas liquid, a nitrogen, a liquefied petroleum gas and combinations thereof.
 11. The method of claim 10, wherein the high salinity water is at least one of a seawater, a reservoir formation water and combinations thereof.
 12. The method of claim 9, wherein the low salinity water is at least one of a desalinated seawater, a diluted seawater, a desalinated hydrocarbon reservoir formation water, a diluted hydrocarbon reservoir water, a river water, a lake water, or a produced hydrocarbon reservoir water.
 13. The method of claim 9, wherein the reservoir is an oil-wet carbonate reservoir, a shale reservoir or a sandstone reservoir.
 14. The method of claim 9, wherein the alternating injection of the low salinity water and the gas is repeated until a water cut is greater than about 80%.
 15. The method of claim 10, wherein the gas is the carbon dioxide.
 16. The method of claim 10, wherein the gas is the natural gas liquid.
 17. A method to enhance recovery of a hydrocarbon in a reservoir, comprising: waterflooding the reservoir with a high salinity water; injecting a first injection of a low salinity water into the reservoir, wherein at least about 0.2 of a pore volume of the reservoir is occupied by the low salinity water; injecting a first injection of a gas into the reservoir, wherein at least about 0.2 of the pore volume of the reservoir is occupied by the gas; alternating at least one additional injection of the low salinity water into the reservoir and at least one additional injection of the gas into the reservoir.
 18. The method of claim 17, further comprising injecting an initial injection of the gas into the reservoir prior to the first injection of the low salinity water into the reservoir.
 19. The method of claim 17, wherein the hydrocarbon is at least one of crude oil or natural gas.
 20. The method of claim 17, wherein the gas is at least one of a carbon dioxide, a natural gas liquid, a nitrogen, or a liquid petroleum gas. 